Fortnightly - alarmhttp://www.fortnightly.com/tags/alarm
enModernization Foundationhttp://www.fortnightly.com/fortnightly/2014/01/modernization-foundation
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Near-term vision for advanced distribution management.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Robert Uluski</p>
</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Robert Uluski</b> (<a href="mailto:ruluski@uisol.com">ruluski@uisol.com</a>) is vice president of DA-DMS systems at UISOL, an Alstom company. </p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - January 2014</div></div></div><div class="field field-name-field-import-image field-type-image field-label-above"><div class="field-label">Image:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/1401-FEA3%20fig1.jpg" width="2060" height="1193" alt="Figure 1 - DMS Data Acquisition and Control Requirements" title="Figure 1 - DMS Data Acquisition and Control Requirements" /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/1401-FEA3%20fig2.jpg" width="1500" height="3514" alt="Figure 2 - Advanced DMS: Expected Benefits" title="Figure 2 - Advanced DMS: Expected Benefits" /></div><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/1401-FEA3%20fig3.jpg" width="2058" height="783" alt="Figure 3 - Monetizing Benefits of DMS Deployment" title="Figure 3 - Monetizing Benefits of DMS Deployment" /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/1401-FEA3%20fig4.jpg" width="2052" height="1701" alt="Figure 4 - DMS-OMS Business Case Benefits" title="Figure 4 - DMS-OMS Business Case Benefits" /></div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>Grid modernization is transforming the operation and management of electric distribution systems from manual, paper-driven business processes to electronic, computer-assisted decision-making. At the center of this business transformation is the distribution management system (DMS), which provides the needed foundation from which optimal levels of performance can be achieved in an increasingly complex business and operating environment. </p>
<p>Electric distribution utilities are facing many new challenges that are dramatically increasing the complexity of operating and managing the electric distribution system: Growing customer expectations for service reliability and power quality, pressure to achieve better efficiency and utilization of existing distribution system assets, and reduction of greenhouse gas emissions by accommodating high penetrations of electric vehicles and distributed generating resources powered by renewable energy sources (wind, solar, etc.). Recent so-called “storm of the century” events in the Northeast U.S. and the lengthy power outages and customer hardships that followed have greatly elevated the need to make power delivery systems more resilient to major storm events and to provide a more effective electric utility response during such regional power grid emergencies.</p>
<p>This article provides a near-term (three to five years) vision for the DMS, discusses the potential benefits, and provides recommendations on how to get started on a DMS project. </p>
<h4>DMS in 2016</h4>
<p>The DMS of the near future will bring extensive functionality, starting with real-time data acquisition and control (DAC), a single distribution system model, and intelligent alarm processing for substation, feeder, and customer facilities. The DMS applications will generate and validate safety protection guarantees (SPG) and switching orders; provide integrated outage and distribution management systems to deliver improved outage management; and perform optimal network reconfiguration. Other components of newer distribution management systems include active management of distributed energy resources (DER) for improved distribution system performance, expanded voltage and VAR control, distribution asset management, and interactive training and simulator environments for emergency preparedness drills, as well as what-if interaction and getting new operators well-trained to operate the distribution grid.</p>
<p>The DAC facilities will deliver information about the status, loading and performance of all electric distribution system components that will enable distribution system operators to operate these devices for optimal system performance without compromising workforce and public safety or asset protection. The DMS will seamlessly acquire information in a secure manner on a nearly-real-time basis from a wide variety of sources including dedicated supervisory control and data acquisition (SCADA), energy management systems (EMS), advanced metering infrastructure (AMI), distribution generators and storage devices, and numerous sensors located throughout the electric distribution system (<i>see Figure 1</i>). Distribution state estimation (DSE) will play a major role in ensuring that information received from the wide variety of sources is consistent and reliable to prevent bad information or missing information from corrupting the results of DMS application software. </p>
<p>Many of the advanced DMS applications require an accurate three-phase electrical model of the distribution system that represents the exact physical and load characteristics of the distribution grid. This model allows the DMS to compute electrical conditions at feeder locations that don’t have any instrumentation. The model should encompass the entire distribution system from the point-of-connection to the transmission system down to the customer meter. The distribution system model must accurately represent the unbalanced characteristic of electric distribution systems (<i>i.e.,</i> different impedance, load, and generation on each phase of the three-phase distribution system). This model also must enable analysis of radial (single source) and networked (multi-source) distribution systems. Several variations of the model are needed: an as-built model that represents the normal configuration of the system; and an as-operated model that represents the current configuration of the system including any temporary modifications (for example, temporary switching, cuts, and jumpers). The DMS also will include an as-planned version of the model to ensure that planned facilities are quickly added to the model when the utility company energizes these devices. The DMS will include facilities for seamlessly building this model from corporate geospatial information system (GIS) data. The incremental update process to bring model changes into the DMS will be handled via electronic transfers with no manual copying and hand-drawn updates. In addition, the model changes should be brought into the DMS with no downtime for the system in a manner that’s transparent to the distribution system operator. </p>
<p>With the massive growth of information from a plethora of new sensors (information sources) out on the distribution system, the potential exists for information overload to the distribution operator. To assist in ensuring that the distribution operator isn’t overwhelmed with information, the DMS will include intelligent alarm-processing functionality that automatically compares measured and calculated quantities against operating limits and alerts the distribution system operators to abnormal operating conditions that require attention. Unlike conventional alarm processing, intelligent alarm processing includes conditional alarm limits to elevate the priority of the alarm messages as operating conditions vary. Intelligent alarm processing will combine related alarm conditions to prevent repeated (nuisance) messages, prioritize each message, and route each message to the person responsible for responding to the event. </p>
<p>Maintaining the safety of the workforce and the general public is of utmost importance. The DMS will manage the business processes for issuing, tracking, and enforcing all safety tags, permits, and clearances in accordance with established safety procedures and will help to ensure that all users and systems are aware of all such operating restrictions. The DMS will also include switch order management (SOM) facilities for creating switching orders that provide the necessary protection for field workers. The DMS SOM application will automatically generate suggested switching actions with due consideration of distributed generators and other complicating factors on the distribution system that are difficult and time consuming to analyze manually. This system will also use unbalanced power flow analysis following each switching step to verify that switching actions do not produce unacceptable electrical conditions (low voltage, equipment overload, etc.). The SOM application also will develop switching plans to restore service following an outage. This will reduce crew time waiting for switching orders to be prepared manually.</p>
<p>Recent major storms (<i>e.g.,</i> Hurricane Sandy) have identified the need for improved mechanisms to better manage the response to such events. Electric utilities have effectively used outage management systems (OMS) for many years during both large and small events. New technologies and application functions, such as improved communications with field crews and new damage assessment capabilities, will improve the operation of such systems. One significant trend is the consolidation of separate outage management and distribution management systems into a single fully integrated system. The integrated architecture enables the distribution operator (or other person in charge) to view the latest customer outage information, distribution equipment status information, and crew availability on a single screen, which vastly improves overall situational awareness and enables the electric distribution utility to more accurately predict estimated time of restoration (ETOR). A feature of the new integrated architecture is that there’s only one model to maintain for DMS and OMS purpose, which will greatly reduce the amount of maintenance effort associated with having two separate models for DMS and OMS. The fault location and investigation process will be greatly improved using last-gasp messages from AMI meters, fault magnitude information from substation protective relay intelligent electronic devices (IEDs), and other sensor inputs that will help predict fault location with more precision than is currently possible. The DMS will also include a contingency analysis function to identify possible equipment failures (loss of a cable or transformer) that could produce an extended customer outage. Knowledge of such possible and plausible contingencies will enable the utility to prepare in advance to meet the contingency by off-loading the equipment in question through planned switching or demand reduction and repositioning mobile substations. The combined OMS/DMS will also include intelligent electronic integration utilizing open Unified Incident Command and Decision Support (UICDS) system standards to enable utilities and regional emergency response personnel to exchange information; Communications between these groups was greatly impaired during recent major events, such as Superstorm Sandy and major ice storms in the Northeast.</p>
<p>The DMS can also become a key investment as part of larger municipal smart-city initiatives where the DMS can help better coordinate utility operations and grid efficiency with regional transportation, water management, police, and fire response. It can also become part of proactive preparations and responses to major events, and can be used to help make manage risks and trade offs between analyzed risks and energy and grid costs. </p>
<p>Many electric distribution utilities are seeking ways to improve the reliability, performance, and efficiency of the distribution system without compromising the safety of the general public and field workforce or sacrificing the level of protection for distribution system assets. The DMS will include an optimal network reconfiguration (ONR) function that will play a significant role in helping to accomplish these objectives during emergencies (outages) and normal operating conditions. During an emergency, ONR will support the concept of a self-healing grid by automatically performing the switching needed to isolate the faulted section of a feeder and then restore power to as many customers as possible that are connected to healthy sections of the feeder. Under normal operating conditions (no outage), ONR will recommend switching actions to improve the overall efficiency and performance of the distribution grid. One example of this type of switching is load balancing, which will transfer load from heavily loaded to lightly loaded feeders to reduce electrical losses.</p>
<p>Much of the activity in distribution grid modernization is centered on DERs, which include distributed generators (DG), distributed renewables (wind and solar power), energy storage units, and controllable loads (<i>i.e.,</i> demand response). The DMS will manage these resources to accomplish a wide variety of business objectives, such as peak shaving and coordination of DERs for market and ancillary services purposes (the so-called “virtual” power plant). Growing DG penetration (especially renewables) can produce reverse power flow conditions, protection problems, and voltage variations that can affect overall power quality. The DMS will help to mitigate these adverse consequences through more intelligent voltage regulation, adaptive protection, load-generation balancing using energy storage, and dynamic voltage control. The DMS will include application software for predicting the output of renewables (solar PV and wind power) based on weather conditions and other factors, thus preparing distribution system operators for near-term operating challenges. </p>
<p>The DMS will also support the microgrid concept in grid-connected mode and island mode. In grid-connected mode, the DMS will maintain the proper balance between load, generation, and storage on the set of feeders and substations that comprise the microgrid. In island mode, the microgrid’s DMS will manage the DERs and control voltage and frequency to ensure acceptable operation when separated from the larger grid. </p>
<p>Optimal voltage and VAR control is another major objective for the DMS. Voltage and VAR control isn’t a new concept. In fact, volt-VAR control has been a fundamental operating requirement for all electric distribution utilities for the entire history of electric power distribution. The primary objective of traditional voltage and VAR control has been to maintain acceptable voltage for all customers at all times (under all loading conditions). As part of grid modernization, many electric distribution utilities are expanding the role of voltage and VAR control to include peak shaving, energy conservation, electrical loss reduction, voltage optimization, and other efficiency improvement measures. The DMS will play a major role in helping to achieve these objectives by providing intelligent control of voltage regulators, capacitor banks, DERs, and dynamic voltage controls under rapidly changing (and often difficult to predict) operating conditions (such as the on-off status of customer-owned generation). </p>
<p>Electric distribution utilities are seeking to maximize the utilization of existing energized assets (especially substation transformers and underground cables) by closely monitoring the operating condition of these assets. The DMS will continuously monitor this critical equipment and inform the distribution system operator when operating limits are being approached. This will allow the operation of these assets with smaller operating margins without jeopardizing the equipment reliability or reducing its lifespan. The DMS also will support dynamic equipment ratings that are based on actual real–time conditions rather than worst case seasonal assumptions. The DMS will also provide the information and algorithms to support condition-based maintenance strategies. </p>
<p>Training distribution system operators to effectively use the new DMS will be a significant undertaking, and is critical to manage the modern distribution grid. Training new operators is already a challenge due to the considerable turnover in operating staff, with more experienced operators retiring and being replaced by less experienced personnel. However, even the most senior distribution system operators will require a significant amount of training on new technologies and operating requirements. DMS-based training simulators, which provide interactive simulation of power system operations under normal circumstances and contingencies, will prepare the operations team to meet these challenges. The training simulator will shorten the time needed to bring new candidate operators up to speed and reduce time spent by senior operators supporting these training activities. Training exercises provided by the simulator will certify that even experienced operators are prepared to meet the new challenges of distribution system operation. In addition, the training simulator will enable the utility to conduct realistic emergency preparedness drills so that the total workforce is prepare to meet the challenges of the next storm of the century.</p>
<p>Figure 2 summarizes the DMS functions, comparing current state and future state, and highlighting expected benefits associated with each function. Acting together as a single integrated platform, the DMS will enable the electric distribution utility to optimize the reliability, efficiency, and overall performance of the electric distribution system, to effectively manage service restoration activities following major storm emergencies, and to fully utilize distributed energy resources.</p>
<h4><b>Getting to the DMS Vision</b></h4>
<p>Most successful DMS implementation projects begin with a thorough assessment of the electric distribution utility’s important business drivers and objectives. These business drivers and objectives provide the foundation upon which all DMS functional and technical design requirements are based. Since the DMS will be expected to serve the needs of the corporation over a long period of time (10 to 15 years at least), it’s important to understand both the short-term needs (over the next three to five years) and the long-term needs (10 to 15 years). </p>
<p>It’s often difficult to anticipate how the business needs of the utility will change in the long term due to the potential impact of external influences that are beyond the control of the electric utility, such as changes in the political, regulatory, and economic environment. To address these uncertainties, the DMS must have a flexible standards-based design that can be expanded as needed in the future to accommodate new requirements that couldn’t be anticipated at project inception. Such a design will help to ensure that the DMS doesn’t become a stranded investment should major new needs arise in the future. </p>
<p>The best way to gain a thorough understanding of corporate business objectives is to interview the people who own the problems: the senior level executives. Besides providing the best available information on current business needs, senior executives are the best resources for obtaining insight into how these business needs are likely to change over the life of the DMS.</p>
<p>Some asset monitoring and control systems, like protective relays, are deemed essential for operating the power grid. It isn’t necessary to develop a business case to economically justify the presence of protective relays, because no electric utility would consider operating the electric system without relays in place. Another example of an essential system is the energy management system (EMS) which manages the operation of the bulk power grid. The potential consequences of losing visibility and control of bulk power grid operations are so severe, that transmission operators will never consider operating without an EMS. There’s no question that an EMS is needed, so a business case isn’t needed to justify its existence. The DMS hasn’t yet reached the status of a mission critical system. The criticality of the DMS is likely to change as the penetration of DERs located on the distribution system grows to a point where the lack of ability to manage these resources threatens the stability of the overall power grid. However, in most regions, this penetration level hasn’t yet occurred. </p>
<p>For the benefit of customers and shareholders alike, it’s essential to know that the expected DMS benefits outweigh the expected deployment and sustainment costs. A major obstacle to deploying DMS is often lack of economic justification. Most DMS applications require a substantial investment of technical and financial resources; therefore, it’s important to determine whether the expected benefits outweigh the investment total cost of ownership (TCO). </p>
<p>Figure 3 illustrates the general procedure for monetizing the functional benefits of DMS deployment. The process starts with identifying the business needs, and then identifying a shortlist of smart grid or grid modernization functions to address these business needs. The utility then analyzes each proposed DMS function to determine the effect or the functional benefit of each application in terms of physical improvements to distribution system reliability, efficiency, and overall performance. Finally, these functional benefits are converted to monetary benefits to enable an apples-to-apples comparison of benefits and costs. Some important benefits that can be used to justify the DMS investment, such as reliability improvement and customer satisfaction, aren’t easily converted to hard monetary benefits. One way to monetize such benefits is to include cost savings in other measures that can be used to accomplish the same benefit. This is often referred to as “bang for the buck” analysis. For example, DMS reliability improvement applications might allow cost savings in equipment replacement and enhanced tree-trimming measures. </p>
<p>A strong business case provides the guiding path to developing the appropriate deployment strategy to derive a quicker payback because the functions deployed will be aligned with the benefits. Monetary benefits can be realized through improved visibility of distribution asset performance, energy efficiency and reliability improvements, peak load shaving and energy conservation, labor savings, increased utilization of distribution system assets, and ability to accommodate higher penetrations of DERs. Energy efficiency improvements are achieved through DMS-managed control strategies that optimize voltage and reactive power for optimal reduction of electrical demand and electrical losses. Reliability improvements are achieved through improved fault locating capabilities (reduces feeder patrol time) and DMS-assisted creation of emergency switching plans (reduces the overall time to restore service). Labor savings are achieved by replacing manual, paper-driven business processes (such as hand-drawn updates to paper feeder maps) with electronic, computer-assisted techniques, yielding reduced overtime, elimination of outside contractors, and reassignment of displaced personnel to other jobs within the company. Miscellaneous monetary benefits include cost savings in rolling out a distribution automation system (centralized DMS model-based approach costs less to implement than decentralized approach) and O&amp;M cost savings achieved via a condition based maintenance (CBM) program managed by the DMS.</p>
<p>Figure 4 presents a representative example of the business case for implementing a combined DMS-OMS at a large North American investor owned utility (IOU). It shows the monetary value of the reliability and energy efficiency improvements, realizable labor savings, and other significant miscellaneous benefits that an IOU expects to achieve by implementing a DMS-OMS. The low-end and high-end amounts represent the expected benefits using very conservative assumptions and less conservative assumptions, respectively. The expected annual monetary benefits range from $5 million to $11 million. For the representative example, the net present value (NPV) of the cost to procure and implement the combined DMS-OMS is approximately $18 million and the NPV of the maintenance costs for the representative system is approximately $5 million. The analysis of revenue requirements using the average of the low end and high end benefits indicates that the net present value of the investment is approximately $38 million with a profitability index (benefit-to-cost ratio) of 2.7. This indicates that the DMS-OMS system is economically justified and provides a respectable return on investment.</p>
<p>One of the major business case challenges is obtaining signoff from senior managers and executives who oversee the project. In some cases, these executives are also responsible for department or project budgets affected by the recommended DMS facilities. For example, if the DMS project is funded in part by workforce productivity improvements, then some workforce cutbacks are needed, possibly in the form of contractor reductions, less overtime, and natural attrition (<i>e.g.,</i> retirements). As another example, if DMS reliability improvement projects are justified based on displacing conventional reliability improvement measures, then cutbacks in the budgets for conventional measures must occur.</p>
<p>The key to obtaining business case signoff and approval is to involve the affected managers and their staff in the preparation of the business requirements and objectives for the new DMS facilities from the very start. To achieve success in this effort, the affected managers and their staff must validate all assumptions, confirm the practicality of the recommended new facilities and their effectiveness in replacing existing human and equipment resources, and in general agree with the recommendations. </p>
<p>Some utilities have already tapped individual elements of the visionary DMS functionality. By 2016, most utilities likely will have some elements of DMS such as basic distribution SCADA, fault location isolation and service restoration (FLISR), or volt-VAR optimization. Leading utilities will have more of the pieces in place, like distributed energy resource management (DERMS) and integrated OMS. Acting together as a single integrated platform, the DMS will enable the electric distribution utility to optimize the reliability, efficiency, and overall performance of the electric distribution system, to effectively manage service restoration activities following major storm emergencies, and to fully utilize distributed energy resources.</p>
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<div class="field-label">Tags:&nbsp;</div>
<div class="field-items">
<a href="/tags/modernization-0">modernization</a><span class="pur_comma">, </span><a href="/tags/distribution-management-system">Distribution management system</a><span class="pur_comma">, </span><a href="/tags/dms">DMS</a><span class="pur_comma">, </span><a href="/tags/reliability">Reliability</a><span class="pur_comma">, </span><a href="/tags/greenhouse-gas">Greenhouse gas</a><span class="pur_comma">, </span><a href="/tags/renewable">Renewable</a><span class="pur_comma">, </span><a href="/tags/data-acquisition-and-control">data acquisition and control</a><span class="pur_comma">, </span><a href="/tags/dac">DAC</a><span class="pur_comma">, </span><a href="/tags/safety">safety</a><span class="pur_comma">, </span><a href="/tags/spg">SPG</a><span class="pur_comma">, </span><a href="/tags/switching">switching</a><span class="pur_comma">, </span><a href="/tags/network">Network</a><span class="pur_comma">, </span><a href="/tags/distributed-energy-resources">Distributed energy resources</a><span class="pur_comma">, </span><a href="/tags/der">DER</a><span class="pur_comma">, </span><a href="/tags/voltage">voltage</a><span class="pur_comma">, </span><a href="/tags/var">VaR</a><span class="pur_comma">, </span><a href="/tags/scada">SCADA</a><span class="pur_comma">, </span><a href="/tags/energy-management-system">Energy management system</a><span class="pur_comma">, </span><a href="/tags/ems">EMS</a><span class="pur_comma">, </span><a href="/tags/metering">metering</a><span class="pur_comma">, </span><a href="/tags/ami">AMI</a><span class="pur_comma">, </span><a href="/tags/dse">DSE</a><span class="pur_comma">, </span><a href="/tags/impedance">impedance</a><span class="pur_comma">, </span><a href="/tags/load">load</a><span class="pur_comma">, </span><a href="/tags/generation">generation</a><span class="pur_comma">, </span><a href="/tags/radial">radial</a><span class="pur_comma">, </span><a href="/tags/built">as-built</a><span class="pur_comma">, </span><a href="/tags/operated">as-operated</a><span class="pur_comma">, </span><a href="/tags/geospatial">geospatial</a><span class="pur_comma">, </span><a href="/tags/gis">GIS</a><span class="pur_comma">, </span><a href="/tags/alarm">alarm</a><span class="pur_comma">, </span><a href="/tags/switch">switch</a><span class="pur_comma">, </span><a href="/tags/order">order</a><span class="pur_comma">, </span><a href="/tags/hurricane-sandy">Hurricane Sandy</a><span class="pur_comma">, </span><a href="/tags/outage">outage</a><span class="pur_comma">, </span><a href="/tags/oms">OMS</a><span class="pur_comma">, </span><a href="/tags/restoration">restoration</a><span class="pur_comma">, </span><a href="/tags/etor">ETOR</a><span class="pur_comma">, </span><a href="/tags/fault">fault</a><span class="pur_comma">, </span><a href="/tags/incident">incident</a><span class="pur_comma">, </span><a href="/tags/uicds">UICDS</a><span class="pur_comma">, </span><a href="/tags/smart-city-0">smart-city</a><span class="pur_comma">, </span><a href="/tags/onr">ONR</a><span class="pur_comma">, </span><a href="/tags/self-healing">self-healing</a><span class="pur_comma">, </span><a href="/tags/wind">Wind</a><span class="pur_comma">, </span><a href="/tags/solar">Solar</a><span class="pur_comma">, </span><a href="/tags/dg">DG</a><span class="pur_comma">, </span><a href="/tags/flow">flow</a><span class="pur_comma">, </span><a href="/tags/island">island</a><span class="pur_comma">, </span><a href="/tags/grid-connected">grid-connected</a><span class="pur_comma">, </span><a href="/tags/training">training</a><span class="pur_comma">, </span><a href="/tags/ownership">ownership</a><span class="pur_comma">, </span><a href="/tags/tco">TCO</a><span class="pur_comma">, </span><a href="/tags/flisr">FLISR</a> </div>
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Sat, 28 Dec 2013 00:59:30 +0000meacott16972 at http://www.fortnightly.com